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• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/60—Compositions for stimulating production by acting on the underground formation
  • C09K8/602—Compositions for stimulating production by acting on the underground formation containing surfactants
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/02—Well-drilling compositions
  • C09K8/03—Specific additives for general use in well-drilling compositions
  • C09K8/035—Organic additives
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/60—Compositions for stimulating production by acting on the underground formation
  • C09K8/62—Compositions for forming crevices or fractures
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/60—Compositions for stimulating production by acting on the underground formation
  • C09K8/62—Compositions for forming crevices or fractures
  • C09K8/66—Compositions based on water or polar solvents
  • C09K8/68—Compositions based on water or polar solvents containing organic compounds
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/60—Compositions for stimulating production by acting on the underground formation
  • C09K8/62—Compositions for forming crevices or fractures
  • C09K8/72—Eroding chemicals, e.g. acids
  • C09K8/74—Eroding chemicals, e.g. acids combined with additives added for specific purposes
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/25—Methods for stimulating production
  • E21B43/26—Methods for stimulating production by forming crevices or fractures
  • E21B43/27—Methods for stimulating production by forming crevices or fractures by use of eroding chemicals, e.g. acids
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
  • C09K2208/30—Viscoelastic surfactants [VES]

Definitions

• the present invention relates to the drilling, completion and stimulation of hydrocarbon- containing formations. More specifically, the invention relates to the viscoelastic surfactant based fluids and methods for utilizing same in gravel packing, cleanup, drilling and fracturing in a subterranean formation.
• Viscoelastic fluids play a very important roles in oilfield applications.
• the viscosity allows the fluids to carry particles from one place to another.
• the drilling fluid is able to carry the drilling cuts from the wellbore to the surface.
• Viscous fluids also play an essential role in gravel packing completion.
• gravel pack operations a steel screen is placed in the wellbore and the viscous completion fluid places prepared gravel of a specific size in the surrounding annulus to minimize the sand production.
• Fracturing fluids are also required to be viscous enough.
• a hydraulic fracture is formed by pumping the fracturing fluid into the wellbore at a rate sufficient to increase pressure downhole to exceed that of the fracture gradient of the rock.
• the fracturing fluid contains the proppant, which keeps an induced hydraulic fracture open after the pressure is released. Therefore it is important for the fluid to have enough viscosity to transport the proppant into the fracture.
• VES viscoelastic surfactants
• VES-based fluids have excellent capacity to suspend and transport sand/proppant.
• VES fluids have several distinctive advantages over polymer-based fluids. Unlike polymer fluids, the VES based fluids are solid free, which minimize the formation damage after they break.
• many viscoelastic surfactants are very sensitive to high concentrated brines. They don't often gel the heavy brines or the fluid viscosity is not stable under high temperature conditions.
• viscoelastic fluids have some limitations for drilling, completion and fracturing applications, especially for deep wells, because many deep wells have bottom hole temperatures of 149 °C (300°F) or more, and they require heavy fluids to balance the well pressure and maintain control of the well.
• VES packages such as VES/low MW polymer, cationic/anioinic surfactants and VES/cosurfactant can successfully viscosify moderate density brines (like CaCI 2 , CaBr 2 and NaBr brine).
• moderate density brines like CaCI 2 , CaBr 2 and NaBr brine.
• none of them can work in heavy ZnBr 2 brine at temperatures above 250 °F under normal dosage (equal or less than 6 vol% as received).
• the ZnBr 2 brine and the mixed brine made by ZnBr 2 /CaBr 2 /CaCI 2 will be used if a density of 15 ppg or higher is needed for deep wells to balance the well
• U.S. Patent Application Publication No. 2002-0033260 describes a high brine carrier fluid having a density of > 1.3g/cm3 (10.8ppg) contains a component selected from organic acids, organic acid salts, and inorganic salts; a cosurfactant that may be sodium
• dodecylbenzene sulfonate SDBS
• sodium dodecylsulfate SDS
• a zwitterionic surfactant preferably a betaine, most preferably an oleyl betaine.
• zinc halides are not preferred, especially zinc bromide.
• the heaviest brine that a useful viscosity was maintained in was at a density of 1.64 g/cm3 (13.7ppg). The highest working temperature is 138°C (280°F).
• U.S. Patent No. 7,148,185 B2 describes the surfactant fluid gels that are stable to brines having densities above about 1.56g/cm3 (13ppg) at high temperatures.
• the well treatments fluids contain a surfactant, preferably erucylamidopropyl betaine, and an amount of alcohol, preferably methanol, and a salt or mixture of salts of a divalent cation or mixture of divalent cations forming a brine, preferably one or more of bromide and/or chlorides of calcium and/or zinc.
• Cosurfactants such as sodium dedecylbeneze sulfonate (SDBS) can also be used.
• SDBS sodium dedecylbeneze sulfonate
• the concentration of surfactant, BET-E-40, shown in the most of examples in heavy brines are 10%.
• the VES fluid/fluid system of the present invention addresses the problem that drilling and production engineers have had for years. More particularly, the VES based fluid system of the invention exhibits significantly improved viscosity in high-density brines at elevated temperatures (>300 °F).
• the present invention generally relates to viscoelastic surfactant based fluids and methods for utilizing same in various oilfield applications including, but not limited to, gravel packing, cleanup, drilling, acidizing and fracturing operations.
• the viscoelastic fluid of the invention comprises at least one amphoteric surfactant and at least one synergistic co- surfactant that increases the gel strength and extends the brine tolerance of said viscoelastic- based fluid.
• Figure 1 is a graph of the effect of cosurfactant A on the viscosity of Armovis EHS in 1 1 .5ppg CaCI2.
• Figure 2 shows the results of viscosity with and without the addition of cosurfactant A in 12.5ppg NaBr.
• Figure 3 shows the test results demonstrating the effect of brine type and cosurfactant on the performance of EHS.
• Figure 4 shows the effect of cosurfactant B in 14.2ppg CaBr2.
• Figure 5 shows the results of viscosity at various shear rates after the addition of cosurfactant B in 14.2ppg CaBr2 at different temperatures.
• Figure 6 shows the excellent results of EHS with the cosurfactant B in 16.5ppg
• Figure 7 is a graph showing the comparison between two surfactant systems in 15.1 ppg ZnBr2/CaBr2.
• Figures 8 and 9 show how long it took EHS /cosurfactant A system for viscosity recovery in 20% CaCI2 at 36°F (100s 1 for Figure 8 and 1 s " for Figure 9).
• Figure 10 shows photos of sand settling test in 14.2ppg CaBr2 containing 6%
• Figure 1 1 shows photos of sand settlingtest in 15ppg CaBr2 viscosified by 6%
• the present invention relates to a VES fluid system that exhibits significantly improved viscosity in high-density brines at elevated temperatures (>300 °F). Numerous rheological experiments have been run to show the excellent viscoelasticity in heavy ZnBr 2 brine (16.5 ppg) up to 400 °F, at a shear rate of 100 s " and pressure of 400psi. Sand settling tests have been conducted at ambient temperature and high temperatures to show the excellent sand suspension properties of this new VES system. VES fluid system of the invention also has an extremely low (-15 °C) pour point, which solves the handling and transportation issues in cold regions.
• the thickened compositions of the present invention can usefully be employed in methods of stimulating and/or modifying the permeability of underground formations, in drilling fluids, completion fluids, workover fluids, acidizing fluids, gravel packing, fracturing and the like. Additionally, the thickened compositions of the present invention can also be employed in cleaning formulations, water-based coatings, detergent formulations, personal care formulations, water based asphalt formulations and the like.
• Viscoelasticity is a desirable rheological feature in drilling fluids, workover or completion fluids, and stimulation fluids which can be provided by fluid modifying agents such as polymeric agents and surfactant gelling agents.
• Viscoelastic fluids are those which exhibit both elastic behavior and viscous behavior. Elasticity is defined as an instant strain (deformation) response of a material to an applied stress. Once the stress is removed, the material returns to its undeformed equilibrium state. This type of behavior is associated with solids. On the other hand, the viscous behavior is defined as a continuous deformation resulting from an applied stress. After a while, the deformation rate (shear rate or strain rate in general) becomes steady. Once the stress is removed, the material does not return to its initial undeformed state.
• Viscoelastic fluids may behave as a viscous fluid or an elastic solid, or a combination of both depending upon the applied stress on the system and the time scale of the observation. Viscoelastic fluids exhibit an elastic response immediately after the stress is applied. After the initial elastic response, the strain relaxes and the fluid starts to flow in a viscous manner. The elastic behaviour of fluids is believed to aid significantly in the transport of solid particles.
• the viscosity of a viscoelastic fluid may also vary with the stress or rate of strain applied. In the case of shear deformations, it is very common that the viscosity of the fluid drops with increasing shear rate or shear stress. This behavior is usually referred to as "shear thinning". Viscoelasticity in fluids that is caused by surfactants can manifest itself shear thinning behavior. For example, when such a fluid is passed through a pump or is in the vicinity of a rotating drill bit, the fluid is in a high shear rate environment and the viscosity is low, resulting in low friction pressures and pumping energy savings. When the shearing stress is abated, the fluid returns to a higher viscosity condition.
• the elastic component of a viscoelastic fluid may also manifest itself in a yield stress value. This allows a viscoelastic fluid to suspend an insoluble material, for example sand or drill cuttings, for a greater time period than a viscous fluid of the same apparent viscosity. Yield stresses that are too high are not a good thing in drilling, as it may make restarting the drilling bit very difficult and causes a condition called "stuck pipe".
• the fluid system of the invention comprises an effective amount of at least one a viscoelastic surfactant and an effective amount of at least one synergistic cosurfactant.
• the viscoelastic surfactant is an amphoteric surfactant that has the general formula (I):
• R- ⁇ is a saturated or unsaturated, hydrocarbon group of from about 17 to about 29 carbon atoms, in another embodiment from about 18 to about 21 carbon atoms.
• R-i is a fatty aliphatic derived from natural fats or oils having an iodine value of from about 1 to about 140, in another embodiment from about 30 to about 90, and in still another embodiment from 40 to about 70.
• Ri may be restricted to a single chain length or may be of mixed chain length such as those groups derived from natural fats and oils or petroleum stocks.
• R 2 and R 3 are each independently selected from a straight chain or branched, alkyl or hydroxyalkyl group of from 1 to about 6 carbon atoms, in another
• R 4 is selected from H, alkyl or hydroxyalkyl groups of from 1 to about 4 carbon atoms; preferably ethyl, hydroxyethyl, OH or methyl.
• k is an integer of from 2-20, in another embodiment 2-12, and in still another embodiment 2-6, and in yet and in still another embodiment 2-4;
• m is an integer of from 1-20, in another embodiment 1-12, and in still another embodiment 1-6, and in still another embodiment 1 -3; and
• n is an integer of from 0-20, in another embodiment 0-12, and in still another embodiment 0-6, and in still another embodiment 0-1.
• the concentration of viscoelastic composition in the fluid is generally from about 0.5% to about 10%, in another embodiment from about 2% to about 8%, and in yet another embodiment from about 3% to about 5% by weight.
• viscoelastic surfactants disclosed and described herein are surfactants that can be added singly or they can be used as a primary component in the aqueous, thickened
• compositions of the present invention examples include, but are not limited to, erucamidopropyl hydroxypropyl sulfobetaine, erucamidopropyl hydroxyethyl sulfobetaine, erucamidopropyl hydroxymethyl sulfobetaine, and combinations and mixtures thereof.
• Armovis EHS an erucamidopropyl hydroxypropylsultaine, caqn be beneficially employed and is available from AkzoNobel, Chicago, Illinois.
• the viscoelastic surfactant is the surfactant of Formula (I) where Ri is unsaturated 21 carbon chain, R 2 and R 3 are methyl group, R 4 is hydroxyl group, k equals 3, both m and n are 1.
• the synergistic co-surfactant increases the gel strength of the viscoelastic-based fluid and extends the brine tolerance. It has the general structure (II) wherein Ri is a saturated or unsaturated, hydrocarbon group of from about 12 to about 22 carbon atoms.
• R 2 , R 3 and R 4 are each independently selected from a straight chain or branched, alkyl or hydroxyalkyl group of from 1 to about 4 carbon atoms; and a hydroxyl group.
• the concentration of the cosurfactant in the fluid is from about 0.1 wt% to about 4%; In another embodiment, the concentration of the cosurfactant in the fluid is about 0.5 wt% to about 1.5 wt%.
• the ratio of surfactant to synergistic co-surfactant is generally from about 1 : 1 to about 15:1 ; in another embodiment from about 2:1 to 15:1 ; in still another embodiment from 3: 1 to about 15; 1 , and in yet another embodiment from 3:1 to about 10:1.
• co-surfactants include, but are not limited to, Arquad T/50 and Ethoquad E/12-75, both of which are available from
• co-surfactants include, but are not limited to, a cationic surfactant of Formula (II) where Ri is unsaturated 18 carbon chain, R 2 , R3 and R 4 is hydroxyl groups; and a cationic surfactant of Formula (II) where Ri is unsaturated 22 carbon chain, R 2 , R 3 are ethylhydroxy groups and R 4 is methyl group.
• High density brines for oilfield use are usually made from salts of divalent cations such as calcium and zinc. Brines made from potassium, ammonium, sodium, cesium and the like may be used as well. Organic cations such as tetramethylammonium can also be employed. Typical inorganic anions for high density brines are chloride and bromide. Organic anions such as formate and acetate may be used. Some combinations of these anions and cations may have to be used to give higher density brines. The selection of one salt over the other or two salts over single salt typically depends on environmental factors.
• a single salt fluid may work during the heat of the summer, whereas during coolertemperatures a two salt fluid may be required due to its lower Truce Crystallization Temperature (TCT), i.e., the temperature at which crystalline solids begin to form when cooled.
• TCT Truce Crystallization Temperature
• the loss of soluble salts, either by settling out or filtration, will drastically reduce the density of treatment fluid. Loss of density can result in a danagerous underbalanced situation.
• the invention will be illustrated by the following non-limiting examples. It is clear from the below examples that the viscoelastic fluid/well stimulation fluid according to the present invention has quite a high density.
• the viscoelastic fluid/well stimulation fluid according to the present invention has a density of greater than 9.5 ppg; in another embodiment, greater than 9.8 ppg; in yet another embodiment, greater than 1 1.5 ppg. Further, in one embodiment, the viscoelastic fluid/well stimulation fluid according to the present invention has a density of 19.2 ppg or less; in another embodiment, 16.5 ppg or less.
• the range of density of the viscoelastic fluid/well stimulation fluid according to the present invention may be greater than 9.5 ppg to 19.2 ppg or less, preferably, greater than 9.8 ppg to 16.5 or less.
• the viscoelastic surfactant used in the examples is Armovis EHS, available from AkzoNobel.
• the co-surfactants used in the examples are cationic cosurfactant A and cationic cosurfactant B.
• Cosurfactant A is Arquad T/50, a cationic surfactant based on tallow amine (Tallowtrimethylammonium chloride).
• Cosurfactant B is Ethoquad E/12-75, an erucyl amine (2) ethoxylate, quarternary ammonium salt. Both cosurfactants are available from AkzoNobel.
• FIG. 1 Shown in Figure 1 is a graph of the effect of cosurfactant A on the viscosity of Armovis EHS in 1 1.5ppg CaCI2. It was observed that the viscosity at low temperatures was significantly increased with the addition of cosurfactant A. The performance at high temperatures was still excellent up to 350F. The viscosity reading was 132cp at 350F at 100s "1 . The results are shown in Figure 1.
• Example 2 Figure 2 shows the results of viscosity with and without the addition of cosurfactant A in 12.5ppg NaBr.
• the low temperature performance was increased dramatically after the addition of cosurfactant A, and the viscosity maintained the viscosity above 100cp up to 330°F.
• Example 3 Shown in Figure 3 are the test results showing the effect of brine type and cosurfactant on the performance of EHS. Tests indicate that the viscosity of EHS only in 14.2ppg CaBr2 was very low at all the examined temperatures, while as, if the brine was replaced by 14.2ppg mixed CaBr2/CaCI2, the viscosity profile was improved a lot, although it was not good enough. The graph also shows the amazing results after the addition of cosurfactant A. It can be seen that the viscosity was doubled at ambient temperature in both of brines, and the performance profile was boosted significantly.
• Figure 5 shows the results of viscosity at various shear rates after the addition of cosurfactant B in 14.2ppg CaBr2 at different temperatures. Obviously, the surfactant in brine behaved as shear-thinning non-Newtonian fluid. The high viscosity at low shear rate indicates the high elasticity of the fluid, over the temperature band of 50-300F.
• ZnBr2 is commonly used for completion, because of its high density. Not many viscoelastic surfactants can work well in ZnBr2 brine, especially in heavy brine with density above 14ppg.
• Figure 6 shows the excellent results of EHS with the cosurfactant B in 16.5ppg ZnBr2/CaBr2/CaCI2 mixed brine. If Armovis EHS was used alone, almost no gelled effect was noticed. However, after the addition of cosurfactant B, the viscosity went up substantially, from ambient temperature to 400°F.
• Example 7 Shown in Figure 7 is a graph showing the comparison between two surfactant systems in 15.1 ppg ZnBr2/CaBr2. It can be seen that there is huge difference with and without the use of cosurfactant B. The maximum working temperature in this particular brine is 250°F. Apparently, based on the result from Figure 6, chloride salt plays an important role in extending the temperature upper limit of surfactants.
• the surfactants were blended in 20% CaCI2 (about 9.8 ppg) to make the gel, in the same way as described in Examples 1 to 7. Then the gel was put in the refrigerator.
• the Grace M5600 Rheometer was used for the measurements. The rheometer was pre-cooled from room temperature by using 1 : 1 ethylene glycol/water as coolant circulator. After the sample was put on the rheometer and the temperature reached 36F, the sample was rotated at a shear rate of 900 s ⁇ for 2 min. Then the rheometer was stopped and restarted immediately with a lower shear rate (100s 1 for Fig 8 and 1 s ⁇ for Fig 9). The changes in viscosity with time were recorded.
• FIGs 8 and 9 show how long it took EHS /cosurfactant A system for viscosity recovery in 20% CaCI2 at 36°F (100s 1 for Fig 8 and 1 s " for Fig 9).
• Sand settling tests were done in 500 ml graduate cylinder.
• 550 ml of the test fluid was prepared using the same mixing procedures as Examples 1-7. Amount of sand (6 pound per gallon) and test fluid to make a total slurry volume of 550 ml were calculated and measured, and then the proppant was added into the bottle containing the test fluid. The whole mixture was shaken vigorously until the proppant was evenly dispersed. Once the slurry was prepared, it was poured into the 500 ml graduated cylinder. Volume of cleared liquid was recorded over a two hour period at room temperature. Then the cylinder was placed in the oven at 180 °F (82 °C ) and preheated for 2 hours before the high temperature test began. It should be noted that several times of vigorous shake may be necessary during 2 hours of preheat.
• Table 1 summaries the results of sand settling test in 14.2ppg CaBr2 containing 6% EHS/Cosurfactant B. At ambient temperature and 180°F, almost no sand settling was observed.
• the sand settling test was also conducted in 15ppg CaBr2 viscosified by 6% EHS/Cosurfactant B. Table 2 shows that almost no sand settled down at 180°F, but it did at room temperature. The total volume that was cleared out after 30 min was 79ml, which was 14.4% of total volume. Shown in Figure 1 1 are some photos of sand settling. Compared to Example 10, it has been found out that heavier brine has less capability to suspend the sand at low temperatures.

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